An oil and gas well is shown in FIG. 1 generally at 60. Well construction involves drilling a hole or borehole 62 in the surface 64 of land or ocean floor. The borehole 62 may be several thousand feet deep, and drilling is continued until the desired depth is reached. Fluids such as oil, gas and water reside in porous rock formations 68. A casing 72 is normally lowered into the borehole 62. The region between the casing 72 and rock formation 68 is filled with cement 70 to provide a hydraulic seal. Usually, tubing 74 is inserted into the hole 62, the tubing 74 including a packer 76 which comprises a seal. A packer fluid 78 is disposed between the casing 72 and tubing 74 annular region. Perforations 80 may be located in the casing 72 and cement 70, into the rock 68, as shown.
Production logging involves obtaining logging information about an active oil, gas or water-injection well while the well is flowing. A logging tool instrument package comprising sensors is lowered into a well, the well is flowed and measurements are taken. Production logging is generally considered the best method of determining actual downhole flow. A well log, a collection of data from measurements made in a well, is generated and is usually presented in a long strip chart paper format that may be in a format specified by the American Petroleum Institute (API), for example.
The general objective of production logging is to provide information for the diagnosis of a well. A wide variety of information is obtainable by production logging, including determining water entry location, flow profile, off depth perforations, gas influx locations, oil influx locations, non-performing perforations, thief zone stealing production, casing leaks, crossflow, flow behind casing, verification of new well flow integrity, and floodwater breakthrough, as examples. The benefits of production logging include increased hydrocarbon production, decreased water production, detection of mechanical problems and well damage, identification of unproductive intervals for remedial action, testing reservoir models, evaluation of drilling or completion effectiveness, monitoring Enhanced Oil Recovery (EOR) process, and increased profits, for example. An expert generally performs interpretation of the logging results.
In current practice, measurements are typically made in the central portion of the wellbore cross-section, such as of spinner rotation rate, fluid density and dielectric constant of the fluid mixture. These data may be interpreted in an attempt to determine the flow rate at any point along the borehole. Influx or exit rate over any interval is then determined by subtracting the flow rates at the two ends of the interval.
In most producing oil and gas wells, the wellbore itself generally contains a large volume percentage or fraction of water, but often little of this water flows to the surface. The water that does flow to the surface enters the wellbore, which usually already contains a large amount of water. The presence of water already in the wellbore, however, makes detection of the additional water entering the wellbore difficult and often beyond the ability of conventional production logging tools.
Furthermore, in deviated and horizontal wells with multiphase flow, and also in some vertical wells, conventional production logging methods are frequently misleading due to complex and varying flow regimes or patterns that cause misleading and non-representative readings. Generally, prior art production logging is performed in these complex flow regimes in the central area of the borehole and yields frequently misleading results, or may possess other severe limitations. Often the location of an influx of water, which is usually the information desired from production logging, is not discernable due to the small change in current measurement responses superimposed upon large variations caused by the multiphase flow conditions.
The problems of production logging in multi-phase flow in conventional production logging are well known and described in the literature. Hill, A. D., et al., in an article entitled, “Production Logging Tool Behavior in Two-Phase Inclined Flow”, JPT, October 1982, pp. 2432-2440, describe the problems of conventional production logging in multiphase wells, stating that for production logging purposes, a well is deviated if it has a deviation over two degrees. Virtually all producing wells have deviations of at least two degrees, and thus virtually all wells are subject to difficult multiphase flow conditions for production logging. Hill et al. also describe the four main types of measurements in use in conventional production logging practice, which are the spinner, dielectric constant, fluid density, and concentrating flowmeter.
A more extensive description of conventional production logging measurements and the problems encountered in multiphase flow is found in a monograph entitled “Production Logging—Theoretical and Interpretative Elements”, by Hill, A. D., Society of Petroleum Engineers, Monograph Volume 14, Richardson, Tex., 1990. In addition, the following publications discuss the problems of measuring multiphase flow in deviated or horizontal wells: “Tests Show Production Logging Problems in Horizontal Gas Wells” by Branagan, P., et al., Oil & Gas Journal, Jan. 10, 1994, pp. 41-45; “Biphasic Fluid Studies for Production Logging in Large-Diameter Deviated Wells” by Kelman, J. S., November-December 1993, The Log Analyst, pp. 6-10; “A Comparison of Predictive Oil/Water Holdup Models for Production Log Interpretation in Vertical and Deviated Wellbores” by Ding, Z. X., et al, SPWLA 35th Annual Logging Symposium Transactions, June 1994, paper KK; and “Production Logging in Horizontal Wellbores” by Nice, S. B., 5th World Oil. Horizontal Well Technol. Int. Conf. (Houston) Proc., sect. 11, November 1993.
While very few wells are actually vertical, the following publication illustrates that conventional production logging may be misleading even in truly vertical wells: “The Effect of Flow From Perforations on Two-Phase Flow: Implications for Production Logging” by Zhu, D., et al., Proceedings SPE Annual Technical Conference and Exhibition, SPE 18207, October 1988, p. 267-75.
U.S. Pat. No. 5,551,287 entitled, “Method of Monitoring Fluids Entering a Wellbore”, issued Sep. 3, 1996 to Maute et al. addresses the above problems. However, the invention has limitations in that it is mechanically complex, and is sensitive in different ways to all three fluids encountered downhole (water, gas, and oil), which results in complex log interpretation, and possibly misleading log interpretation. For example, the interpretation may be misleading if gas does not cool upon entry to the wellbore, as it usually but not always does. The interpretation is also complicated when the wellbore contains a significant amount of non-produced water as is generally the case, making the distinguishing of inflow of water from non-produced water difficult and ambiguous. In addition, the tool is designed for only one casing diameter, and cannot readily accommodate any significantly different diameter, as does occur in many wells. Furthermore, a large amount of data is needed from each of the multitude of pads (eight or more), each of which has three different sensors.